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Nov 21, 2013 (3 years and 6 months ago)

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Recommendations on a Vision and
Direction for the Future of the Electric
Power Grid in the Commonwealth

The Kentucky Smart Grid Roadmap Initiative
Kentucky’s
Smart Grid Roadmap


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PURPOSE
The Kentucky Smart Grid Roadmap Initiative (KSGRI) is an effort to identify a path towards electric grid
modernization in the Commonwealth of Kentucky. The KSGRI includes inputs from academic, electric
utility, governmental, and stakeholder representatives.
The KSGRI is led by the University of Louisville’s Conn Center for Renewable Energy Research (“Conn
Center”) and the University of Kentucky’s Power and Energy Institute of Kentucky (“PEIK”). The Conn
Center and PEIK were engaged by the Kentucky Public Service Commission (“Kentucky Commission”) to
develop a technical roadmap for developing and deploying “Smart Grid” technology throughout the
Commonwealth. Their efforts were monitored and reviewed by Staff from the Kentucky Commission;
however, this report, its conclusions and recommendations do not reflect the opinion or position of the
Staff of the Kentucky Commission or of the Commission, itself. The KSGRI has also brought together
broad representation from the electric utility industry, state government, and other closely related
industries for information and consultation.
The Kentucky Smart Grid Roadmap is the end result of a 2 year project by the KSGRI to analyze the
existing power infrastructure in Kentucky and to develop recommendations for future grid
modernization efforts. The goals of the Kentucky Smart Grid Roadmap are to facilitate the following
outcomes:
1. Maintain Kentucky’s energy security though prudent deployment of advanced Smart Grid
technologies.
2. Improve electric energy efficiency, reliability, and safety of the Kentucky electric power system.
3. Facilitate academic, industrial, and governmental partnerships to position Kentucky at the
forefront of Smart Grid analysis in the areas of technology development and deployment, and
public policy.
4. Educate consumers, utility representatives, government representatives, and others on the
benefits, risks, and barriers associated with Smart Grid technology deployments.
It is our belief that adoption of Smart Grid technologies will bring improvements to the Kentucky
electrical grid in the areas of reliability, safety, security, price, environmental impacts, and efficiency.

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CONTRIBUTORS
KY SMART GRID ROADMAP INITIATIVE COMMITTEE
Primary Authors
Mr. Yan Du - Department of Electrical and Computer Engineering, University of Kentucky
Dr. Matthew Turner - Conn Center for Renewable Energy Research, University of Louisville

Contributing Authors
Dr. Adel Elmaghraby - Department of Computer Engineering and Computer Science, University of
Louisville
Dr. James Graham - Department of Electrical and Computer Engineering, University of Louisville
Dr. Yuan Liao - Department of Electrical and Computer Engineering, University of Kentucky
Dr. John Naber - Department of Electrical and Computer Engineering, University of Louisville
Dr. Mahendra Sunkara - Conn Center for Renewable Energy Research, University of Louisville

KENTUCKY PUBLIC SERVICE COMMISSION ADVISORY PANEL
Ms. Kimra Cole - Engineering Division, Kentucky Public Service Commission
Mr. Jeff Derouen, J.D. - Executive Directors Office, Kentucky Public Service Commission
Mr. James Gardner, J.D. - Vice Chairman, Kentucky Public Service Commission
Mr. Aaron Greenwell - Executive Directors Office, Kentucky Public Service Commission
Dr. John Rogness - Division of Financial Analysis, Kentucky Public Service Commission

CONTRIBUTING UTILITY PARTNERS
Mark Abner - Cumberland Valley Electric, Inc.
Avery Adams – Duke Energy
Tracy Bensley - Jackson Purchase Energy
Corporation
James Bridge - Owen Electric Cooperative
Ken Cooper - Bluegrass Energy Cooperative
Rocco D’Ascenzo - Duke Energy
Tim Duff - Duke Energy
Paul Dollof - East Kentucky Power Cooperative
Mike French - Meade County RECC
David Graham - Shelby Energy Cooperative, Inc.
Marvin Graham - Inter-County Energy
Cooperative
Gary Grubbs - Shelby Energy Cooperative, Inc.
Greg Harrington - Nolin RECC
Roger Hickman - Big Rivers Electric Corporation
Dennis Holt - South Kentucky RECC
David Huff - Louisville Gas & Electric and
Kentucky Utilities, LLC
Brandon Hunt - Fleming Mason Energy
Rick Lovekamp - Louisville Gas & Electric and
Kentucky Utilities, LLC
Lila Munsey - Kentucky Power
Jeff Myers - Louisville Gas & Electric and
Kentucky Utilities, LLC
John Newland - Kenergy Corp.
John Patterson - Taylor County RECC
Todd Peyton - Clark Energy Cooperative
Russ Pogue - Big Rivers Electric Corporation
Brian Poling - Grayson RECC
Jeff Prater - Big Sandy RECC
Mike Scaggs - Taylor County RECC
Isaac Scott - East Kentucky Power Cooperative
James See - Owen Electric Cooperative
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Tim Sharp - Salt River Electric
Mark Stallions - Owen Electric Cooperative
Scott Sidwell - Clark Energy Cooperative
Tom Weaver – AEP, Kentucky Power
Carol Wright - Jackson Energy Cooperative

CONTRIBUTING STAKEHOLDER PARTNERS
Bill Burke – GE Consumer and Industrial
Paul Centolella – Commissioner Emeritus, PUC
Ohio
Rick Clewett – Sierra Club
Bill Dawson – Greater Louisville Inc.
Steve Dale – Kentucky Department for Energy
Development and Independence
Tom Dorman – Office of Kentucky
Representative Rock Adkins
Robert Duff – Kentucky Department for Energy
Development and Independence
Venkat Krishnan – GE Consumer and Industrial
Robert Amato - Kentucky Energy & Environment
Cabinet, Department for Energy Development
and Independence
Jeff Auxier - Kentucky Solar Energy Society
Alfred Gaspari - Greater Cincinnati Energy
Alliance
B. Russell Harper - Kentucky Council of Area
Development Districts
Dan Hoffman - RegenEn Solar
Dennis Howard – Kentucky Agriculture Cabinet
Paul Hornack - Kentucky State Senate
Susan Lambert - Earthworks, LLC
Alan Manche – Schneider Electric
Wallace McMullen - Cumberland Sierra Club
John Robbins – Sierra Club
Ron Willhite - Kentucky School Board
Association



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TABLE OF CONTENTS
Purpose ......................................................................................................................................................... 2
Contributors .................................................................................................................................................. 3
KY Smart Grid Roadmap Initiative Committee.......................................................................................... 3
Kentucky Public Service Commission Advisory Panel ............................................................................... 3
Contributing Utility Partners ..................................................................................................................... 3
Contributing Stakeholder Partners ........................................................................................................... 4
Table Of Contents ......................................................................................................................................... 5
Executive Summary and Key Recommendations .......................................................................................... 7
Chapter 1: About the Kentucky Smart Grid Roadmap Initiative ................................................................... 8
Chapter 2: A Smart Grid Primer .................................................................................................................. 10
What is the “Grid”? ................................................................................................................................. 10
What is a “Smart Grid”? .......................................................................................................................... 11
The Six Smart Grid Infrastructure Areas ................................................................................................. 12
Chapter 3: The Smart Grid Value Chain ...................................................................................................... 15
How does Smart Grid benefit consumers? ............................................................................................. 15
How does Smart Grid benefit utilities? ................................................................................................... 16
How does Smart Grid benefit society at large? ...................................................................................... 16
Chapter 4: Smart Grid Technology Adoption .............................................................................................. 18
A 50,000 Foot Overview of The Kentucky Electrical Grid ....................................................................... 18
Where Are We Now and Where Do We Want to Go? ............................................................................ 19
The State of Advanced Metering Infrastructure ..................................................................................... 21
The State of Distribution ......................................................................................................................... 25
The State of Transmission ....................................................................................................................... 29
The State of Asset Management ............................................................................................................. 32
The State of Distributed Energy Resources ............................................................................................ 34
The State of Consumer Education .......................................................................................................... 37
Chapter 5: Summary of Kentucky Smart Grid Workshop Series Results and Key Action Items ................. 39
Workshop Key Results ............................................................................................................................ 39
Chapter 6: Barriers to Smart Grid Deployments ......................................................................................... 41
Customer Acceptance Barriers ............................................................................................................... 41
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Technological Barriers ............................................................................................................................. 41
Regulatory and Policy Barriers ................................................................................................................ 42
Business and Financial Challenges .......................................................................................................... 42
Chapter 7: The Kentucky Smart Grid Roadmap .......................................................................................... 43
Kentucky Smart Grid Taskforce ............................................................................................................... 43
Infrastructure Deployments.................................................................................................................... 43
Awareness, Marketing and Education .................................................................................................... 46
Research and Development and Pilot Programs .................................................................................... 47

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EXECUTIVE SUMMARY AND KEY RECOMMENDATIONS
The Kentucky Smart Grid Roadmap is focused on the modernization of the electric power grid in the
state of Kentucky in the areas of generation, transmission, distribution, metering, and the end-use of
electricity, as well as consumer education. Its goal is to make recommendations that will guide capital
and resource investment decisions made by utilities, regulatory and policy decisions made by state
government, and research and development activities of universities.
Grid modernization is of critical importance, both nationally and within the Commonwealth. Broadly,
this means the ability to meet ever increasing standards in reliability, security, cost of service, power
quality, efficiency, environmental impact and safety, and the ability to measure our progress towards
these goals. Deployments of smart grid technology can create a grid that is self-healing, optimizes the
utilization of system assets, enables new energy markets, encourages the integration of all types of
electricity generation and energy storage, provides digital grade power, and is resistant to attack and
natural disaster. However, the technologies that enable Smart Grid are still emergent and the economic
justification is still evolving.
The KSGRI brought together more than 70 stakeholders from academia, the electric utility industry,
governmental agencies, non-profit groups, and industrial and consumer energy users. These
stakeholders provided insight into the operation of the Kentucky electric power system, identified
opportunities and barriers for grid modernization, and provided opinions used to form key
recommendations on a plan that will ensure an integrated and comprehensive approach to Smart Grid
deployments in the Commonwealth.
The 5 key recommendations of the KSGRI are:
1. Encourage investments focused on future-proof data network architecture, preferably one that
is Internet Protocol based.
2. Creation of an official Kentucky Smart Grid Council composed of academic, industrial,
governmental, and stakeholder members.
3. Funding of energy /technology policy and technology development research within the state
university system.
4. Creation of regulatory mechanisms to foster increased investments in both cost-effective
demand response programs and energy efficiency technologies such as Volt/VAR.
5. Allow for real-time and multi-tariff pricing.
6. Establishment of clear metrics to establish priorities and goals for Smart Grid deployments in KY.

Funding for the KSGRI comes from the United States Department of Energy’s National Energy
Technology Laboratory through the American Renewal and Reinvestment Act and is sponsored by the
Kentucky Public Service Commission.
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CHAPTER 1: ABOUT THE KENTUCKY SMART GRID ROADMAP
INITIATIVE

Our challenge is to consider current electrical infrastructure, existing and emerging
technologies, societal and consumer value, and economic and political conditions to
create a grid vision that is appropriate for Kentucky. Once defined, this Smart Grid vision
will help to guide infrastructure and technology investments made in Kentucky.
The Kentucky Public Service Commission engaged the University of Louisville and the University
of Kentucky to form a partnership, the KSGRI, to develop analyses, recommendations, and a
technical roadmap for the development and deployment of Smart Grid technologies throughout
the Commonwealth regarding:
1. the condition of Kentucky’s existing electric transmission grid;
2. which existing and emerging technologies are most likely to yield operational
efficiencies and reliability benefits to Kentucky’s electric transmission grid if
appropriately deployed by utilities;
3. the degree to which Kentucky’s electric generating utilities have already incorporated
advanced technology in their transmission systems;
4. the “smartness” of Kentucky’s existing electric distribution system;
5. which existing and emerging technologies are most likely to yield operational
efficiencies and reliability benefits to Kentucky’s electric distribution system if
appropriately deployed by utilities;
6. the degree to which Kentucky’s electric distribution utilities have already incorporated
advanced
7. the availability of technologies and equipment/appliances to establish smart-grid
facilities (i.e. residences, small business, etc.);
8. the extent to which Kentucky utilities may assure that any Smart Grid technologies
deployed in the short-term will be compatible with future technology advances;
9. a timeline for deploying Smart Grid technology throughout Kentucky’s transmission,
distribution and facility-level networks;
10. a survey and analysis of available funding sources (i.e. rates, grants, loans, etc.) for
Smart Grid technology;
11. the rate structures that will be necessary to make Smart Grid technology economically
feasible (i.e. time of day rates, peak pricing, etc.); and
12. any legal barriers to development and deployment of Smart Grid technology.

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This “Kentucky Smart Grid Roadmap” provides recommendations and best practices to utilities and
utility stakeholders to guide individual Smart Grid deployment approaches. As part of the roadmap
development, the KSGRI team analyzed existing and planned Smart Grid deployments within the
commonwealth.
Analysis of existing and planned Smart Grid deployments were performed using interrogatories sent to
all jurisdictional utilities. These self-reporting surveys collected information in the areas of general
Smart Grid deployments and planning, advanced metering, distribution operations, transmission
operations, asset management, distributed energy resource deployments, and customer education
programs. An analysis and summary of these interrogatories was performed and reported in Smart
Grids in the Commonwealth of Kentucky: Final Report of the Kentucky Smart Grid Roadmap Initiative.
In tandem to the analysis of the existing deployments, the KSGRI hosted a series of Smart Grid
workshops that gathered key stakeholders from academia, the utility industry, state government, and
other organizations to discuss Smart Grid issues as they relate to the Commonwealth. These workshops
addressed factors likely to inhibit or encourage Smart Grid deployments, the current state and future
needs of KY’s electrical infrastructure and technologies, and market and public policy approaches to
facilitate Smart Grid deployments.
Combined, the above efforts provide the inputs which the KSGRI utilized to form the recommendations
presented in this document. As such, these recommendations do not necessarily represent the
individual views of either the contributing partners or the Public Service Commission Advisory Panel.

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CHAPTER 2: A SMART GRID PRIMER
WHAT IS THE “GRID”?
In the power industry, the term “electric grid” or “the grid” refers to an interconnected network
responsible for delivering electricity from electrical generators to electricity consumers. Generally, the
grid is made up of three primary components:
1. Power generation—where various energy sources are converted into electricity. Power plants
are usually centralized stations and utilize energy sources such as coal, hydro, nuclear, natural gas,
solar and wind to generate large amount electricity, although there are also small amount
distributed generations such as residential roof-top solar panels. The electricity generated at the
power plants is stepped up to a transmission voltage by transformers which are connected to the
transmission lines.
2. Power transmission—which is an interconnected network for carrying high voltage bulk
electricity from power plants through long distance transmission lines until it reaches distribution
systems where the electricity will be stepped down to a distribution voltage for local dispatch.
3. Power distribution—which is the local network for delivering electricity at the distribution
voltage from distribution substations to electrical service locations where the electricity is further
stepped down to the service voltage before it is ready to be consumed by customers.

The traditional electric grid has been in place since mid-19
th
century. Although it keeps evolving with the
change of the external and internal environment including new regulations, a changing economy,
evolving technologies, etc., the basic infrastructure remains what it looked like half century ago. Below
is an illustration of the primary components of the traditional grid.

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WHAT IS A “SMART GRID”?
The electric power grid operated by Kentucky’s jurisdictional electric utilities serves more than 1.8
million customers that are connected together by more than 33 thousand miles of transmission and 98
thousand miles of distribution lines. This grid has served as the backbone of the modern energy
economy of Kentucky, and has provided residents of the commonwealth with safe, reliable, and low-
cost electrical power for generations. However, the current electric grid faces unprecedented pressures,
including aging infrastructure, outdated technologies, increasing energy costs, and increased
environmental scrutiny.
A Smart Grid addresses these emerging issues through the application of modern technologies, digital
communications infrastructure, and new business and operational methodologies applied to the
operation of the electric power system. Many of these technologies can be deployed within the very
near future or have already been deployed in Kentucky. For example, Supervisory Control and Data
Acquisition (SCADA) systems enable auto-restoration and real-time monitoring of critical power system
elements.
However there also exists an opportunity to greatly improve the overall future intelligence and
operational efficiency of the grid by strategically investing in the network technologies that will allow
the leveraging of energy information to create an architecture that is robust, flexible, and adaptable.
The illustration below presents a probable design, although the exact technological makeup of a Smart
Grid will vary from utility to utility.

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THE SIX SMART GRID INFRASTRUCTURE AREAS
Smart Grid is more than just new devices. At its core, Smart Grid is about the combination of new
technologies with data network architecture to gain efficiency and create new operational models. As
such, the KSGRI divides Smart Grid into six Infrastructure Areas:
1. Advanced Metering
2. Advanced Distribution
3. Advanced Transmission
4. Advanced Asset Management
5. Consumer Education
6. Distributed Energy Resources
Advanced Metering Infrastructure (AMI)
AMI refers to the integration of a variety of systems in order to establish two way communications
between the customer and the utility and to provide each with time stamped system information.
The following figure shows a typical residential AMI configuration. The smart meter is installed at the
residential house, and has the capability to record, transmit, receive, and display usage information on
an in home display or a computer. The in-home display serves at the foundation of the home area
network. Additionally, the smart meter communicates with an integrated communications device
installed at a nearby utility pole. Two-way communications take place between residence and utility
office via the integrated communications systems. The utility office implements the Meter Data
Management system to collect and analyze data, as well as to enable interaction with other information
systems. Industrial and commercial AMI have similar configurations.
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The following figure provides a summary of ADO functions. From a systems perspective, ADO includes
Advanced Distribution Automation (ADA) that enables intelligent control over electrical power grid
functions such as Fault Location, Isolation and Service Restoration (FLIR), Conservation Voltage
Reduction (also known as Volt/VAR control or VVC), Distribution system Operation Modeling and
Analysis (DOMA), Data Acquisition and Control (DAC), and other sub-functions. ADO also aids
deployment of distributed energy resources (DER), such as renewable energy resources and electric
vehicles (EV), and enables the operation of microgrids. It can be integrated with a distribution-level
geographical information system (GIS) and distribution supervisory control and data acquisition (SCADA)
system for improved grid awareness.


Advanced Transmission Operation (ADO)
The purpose of ATO is to increase the intelligence and capacity of the nation’s high-voltage electric
transmissions system through the application of advanced digital technology and power electronic
devices to gain improvements in transmission reliability, utilization, and efficiency. This includes an
improved ability to manage congestion, scheduling, and planning for the system, an increase in
substation automation, improvements to automated protection and control, more accurate and more
frequent system modeling and simulation , and the use of advanced grid control devices and materials.
Additionally, ATO can help to integrate operation and planning functions among power markets,
Regional Transmission Organizations (RTO) and Independent System Operators (ISO).
Advanced Asset Management (AAM)
AAM is the use of the grid intelligence to improve system asset management applications in order to
reduce operations, maintenance, and capital costs, and to better utilize assets efficiently during day-to-
day operations. AAM can help to significantly improve the performance of capacity planning,
forecasting, maintenance, engineering and facility design, customer service processes, and work and
resource management. AAM is not limited to one part of the electric grid, and can be applied to
generation, transmission, distribution, and end-use of electricity by the consumer.
Consumer Education (CE)
Many of the advanced solutions Smart Grid can offer are dependent upon the acceptance of new
technologies and the behaviors of end-use consumers. However up to 75 percent of the population are
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unfamiliar with the Smart Grid concept. Through education programs, customers can become better
informed and take a more active role in personal energy management. Of particular importance are
programs to inform customers on smart meters, demand response programs, energy efficiency
program, and distributed energy resources.
Distributed Energy Resources (DER)
DERs are small, modular, decentralized energy generation and storage technologies that can produce
electricity where energy is needed. They are "distributed" because they are located at or close to the
point of energy consumption, unlike traditional "centralized" systems, where electricity is generated at a
remote large-scale power plant and then delivered through power lines to the consumers. DER includes
renewable energy resources, distributed generations, and energy storage resources, and it is playing an
increasingly important role in the nation's energy portfolio. DER has the potential to mitigate congestion
on transmission lines, reduce the impact of energy price fluctuations, enhance energy security, improve
power reliability and stability, and can have significant impact on the environment and natural
resources.

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CHAPTER 3: THE SMART GRID VALUE CHAIN
Today’s economy and lifestyle have become inextricably linked to electricity, with a dependence on
devices such as computers, networks, robotics, medical devices, and air conditioning. Additionally,
electricity has come to support an increasingly digital modern world. For example, in the early 80’s the
percentage of electrical load composed of digital semi-conductor devices was negligible and today has
eclipsed 20 percent while showing signs of continued growth. Therefore proper infrastructure that
supports a digital economy and that facilitates continued economic growth is critical to the success of
every Kentuckian. Reliable electrical infrastructure is a critical component to establishing global
competitiveness. As other regions in the world upgrade their electrical power systems, the U.S. will
have no choice but to follow suit in order to create and maintain a competitive advantage.
Problems with the American grid have already
been identified. Nationally, 70 percent of
transmission lines and transformers are 25 years
old or older and 60 percent of circuit breakers are
30 years old or older. Much of the system was
designed in the 1950’s and was installed in the
60’s and 70’s before the microprocessor
revolution. Despite this, electric utility funded
R&D nationally has been minimal. In fact, a
National Science Foundation survey shows the
national average to be 0.2 percent of net revenue,
placing electric utilities at

1/20th the average of
all U.S. industries.
Studies by the Department of Energy’s National Engineering Technology Laboratory and the Electric
Power Research Institute have estimated the total cost of upgrading the American power grid to be
$165 Billion over the next 20 years, with $127B for distribution level systems and $38B for transmission.
This equates to a total required additional national investment of $8.3B per year for 20 years, which is
incremental to the current annual investment of $18B. However, the same studies have quantified the
benefits of grid modernization as between $638B and $802B over the next 20 years with an overall
benefit to cost ration of 4:1 to 5:1:
“Thus, based on the underlying assumptions, this comparison shows that the benefits of
the envisioned Future Power Delivery System significantly outweigh the costs. (EPRI,
2004
1
)”
HOW DOES SMART GRID BENEFIT CONSUMERS?

1

http://www.netl.doe.gov/smartgrid/referenceshelf/presentations/E_forum_2_SG%20Benefits%20and%20Challenges
_APPROVED_2008_06_02.pdf

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The Smart Grid can deliver significant benefits to consumers by transforming access to information. By
providing utility customers with detailed energy consumption information, Smart Grid technology can
facilitate new controls and options that include:
· The ability to manage energy consumption.
· The ability to better enable customers to participate in demand response programs.
· Convenient interconnection of distributed generation such as roof-top solar.
· Reduction in the number and duration of outages.
· And an improved overall level of service quality and reliability.

HOW DOES SMART GRID BENEFIT UTILITIES?
By upgrading the grid with smart technologies, utilities can increase customer satisfaction and reduce
operation ,maintenance, personnel, and capital costs. An integration of a digital network across
generation, transmission, distribution, and end-use of electricity by consumers can enable operational
efficiencies in the areas of:
· Metering and billing
· Outage management
· Process improvement
· Work force management
· Reduced losses (energy)
· Asset utilization
Additionally, data from these systems can be leveraged to gain improvements in asset management for:
· System planning
· Maintenance practices
· Engineering
· Grid monitoring

HOW DOES SMART GRID BENEFIT SOCIETY AT LARGE?
The benefits of Smart Grid deployments are not limited to customers and utilities. Improved operating
and market efficiencies can lead to downward pressure on electricity prices that increase the
competitiveness of American business both domestically and internationally, which in turn can improve
job and GDP growth. By increasing the robustness of the grid improvements are made in national
security as well as public and worker safety. Plug and play integration of distributed energy resources
such as renewable generation improves the security of the American energy supply against changes in
international fuel supplies. Integration of renewables and a reduction in energy losses facilitated by
Smart Grid can reduce emissions from carbon based fuel sources. Finally, the Smart Grid presents the
opportunity to revolutionize the transportation sector, moving to electrified transit that is quieter,
cleaner, and potentially cheaper.
Although the benefits of Smart Grid deployment can be significant, Smart Grid technologies are not a
silver bullet to solve the challenges facing the American electric grid and potential deployments must be
evaluated. The following examples illustrate different regulatory approaches utilized to evaluate Smart
Grid:
Vermont Department of Public Service
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Vermont House Bill 313 directed the pursuit of the American Recovery and Reinvestment Act (ARRA)
funding opportunities by the Department of Public Service to implement Smart Grid technologies,
projects, and workforce training.
A grant application known as eEnergy Vermont was filed by Vermont Electric Power Company (VELCO)
with DOE, on behalf of Vermont's 20 distribution utilities, with the support of the Department of Public
Service, Efficiency Vermont, the Office of Economic Stimulus and Recovery, as well as Vermont's
congressional delegation.
In October 2009, Vermont's electric utilities were awarded approximately $69 million in ARRA funds to
cover half of the cost of modernizing the electric grid over the next three years. The project will move
the state toward development of a statewide Smart Grid, using digital technology to convert the electric
infrastructure to a two-way information system. These grid updates will lay the foundation for a fully
integrated Central Vermont Public Service SmartPower system.
Specific eEnergy Vermont goals are to:
· Deploy smart meters to over 90 percent of Vermont premises.
· Pilot the use of in-home devices for communicating and controlling consumer energy patterns.
· Study dynamic rate structures enabled by smart meter technology.
· Deploy automated controls to the grid and substations.
Because of a high level of cooperative effort among Vermont’s utilities and public entities, Vermont has
an opportunity to build a statewide Smart Grid that can serve as a model for the rest of the country. “
Maryland Public Utility Commission on Delmarva Power’s AMI proposal
The Public Utility Commission of Maryland opened an administrative case with an order approving an
AMI proposal from Delmarva Power, stating that “Delmarva’s modified business plan complies with the
AMI Order, satisfies our previous concerns and likely will be cost-effective to Delmarva ratepayers."
However, some significant caveats were also included along with the approval in the order. Smart Grid
analysts (SmartGridNews.com) have interpreted the ruling to say that though PUC granted the
authorization to allow Delmarva to proceed with the deployment of the AMI program, it did not mean
that the program is prudent, and the PUC will require Delmarva to demonstrate that the AMI project is a
cost-effective program for its Maryland customers before PUC issues cost recovery authorization. If the
AMI proposal later falls short of the standard as implemented, Delmarva will need to bear the risks, not
the ratepayers, and the PUC will determine the level of cost recovery the public requires.

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CHAPTER 4: SMART GRID TECHNOLOGY ADOPTION
A 50,000 FOOT OVERVIEW OF THE KENTUCKY ELECTRICAL GRID
As of February 2012, Kentucky’s jurisdictional utilities include three investor owned utilities (IOUs)
2
, two
generation and transmissions cooperatives (G&Ts) and 19 distribution cooperatives. Of the 23 utilities
that participated in the KSGRI, five utilities operate in the generation and transmission markets, and 21
operate in the distribution market. In all, the responding jurisdictional utilities employ approximately
6310 workers in Kentucky and provided service to 1,572,922 residential customers, 219,603
commercial/industrial customers, and 15,974 other customers (largely street lighting).
The average size of the service territory in KY is 1,971 square miles, with a statewide average of 11.1
customers per line mile of distribution line (state average of 9.8 customers/line mile for cooperatives
and 22 customers/line mile for investor owned utilities). The utilities collectively operate 33,844 miles of
transmission and 98,399 miles of distribution within KY. There are approximately 2,008,700 electric
meters, with a total penetration rate of AMI-capable “smart” meters of 22 percent.
The statewide average System Average Interruption Frequency Index (SAIFI) is 1.4 interruptions per
customers, as compared to the U.S. median of 1.10. The statewide average System Average
Interruption Duration Index (SAIDI) is 137, compared to a U.S. median of 90 minutes. The statewide
average distribution system line loss is 4.675 percent.
The reported cost to operate the electric transmission system is $74,067,312 annually (excluding Duke
Energy). The reported cost to operate the electric distribution system is $375,480,680 annually
(excluding Duke Energy, and Grayson RECC). This equates to an average cost per customer of $552.85.
Demand Response (DR) offerings consist primarily of the use of a remotely-addressable switch to
interrupt customer loads such as air conditioning units, pool pumps, heat pumps and electric water
heaters. Statewide, over 167,000 (≈9 percent) customers participate in direct load control programs,
with average peak reductions ranging from 6.7 MW to 116 MW (summer). All responding utilities
reported that they are not currently prepared to implement dynamic pricing.
Other modernization practices have been limited in deployment. Those reported include smart meter
pilots, conservation voltage reduction, and automatic circuit reconfiguration for outage
management/self-healing. Of the responding utilities, six indicated having multi-year plans specifically
targeting Smart Grid deployments. Of these six, three are specifically focused on AMI deployments.
Regarding the development of the modern grid, utilities have identified transmission limitations and
constraints as top priorities, followed by generation constraints. Specific concerns regarding the
implementation of Smart Grid programs include the need for cost recovery / economic justification of
programs, technical obsolescence, and regulatory mandates.


2
Louisville Gas & Electric and Kentucky Utilities considered as a single entity.
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WHERE ARE WE NOW AND WHERE DO WE WANT TO GO?
The KSGRI created the Kentucky Smart Grid Assessment Mode (KSGAM) to measure the extent of Smart
Grid deployments, operations, and planning in Kentucky, to determine priorities for areas of
improvement within the state electrical grid, and to include stakeholder input as to what our societal
priorities for a modern grid should be.
The KSGAM divided Smart Grid operation into 10 groupings of related characteristics defining Smart
Grid operations. These groupings, called Smart Grid Classes, are:
1. Strategy and Management (SM): Smart Grid vision and strategic planning, internal governance
and management processes, and collaboration with internal and external stakeholders.
2. Organization and Structure (OS): workplace structure, training, communications, and knowledge
management within the utility.
3. Technology (TECH): deployment evaluation and strategic planning of advanced technologies.
4. System Architecture and Operation (SAO): operation of the power grid as an automated system
with a high degree of situational awareness.
5. Demand and Supply Management (DSM): dynamic management of supply and demand based
on real-time information, particularly for load management and distributed energy resources.
6. Work and Asset Management (WAM): optimal management of grid assets and workforce
resources, with decisions based on real-time data.
7. Physical and Cyber Security (SEC): protection of equipment and data from cyber and physical
security attacks through security architectures, risk assessments, and cyber security standards.
8. Government and Regulation (GR): the extent to which regulators authorize Smart Grid
investments, approve innovative regulatory strategies, and facilitate intra-utility optimization.
9. Customer (CUST): the role of customer participation and experience, regarding pricing,
education, and advanced services.
10. Environment and Society (ENV): contributions of the utility to achieving societal goals regarding
reliability, safety, security, energy sources, energy source impacts, and quality of life.
For each of these 10 groupings, the utilities
were given a list of characteristics divided into
five levels, ranging from level 0 to level 5. Using
these lists, utilities indicated the “As-Is” state of
their systems. Statewide, utilities report that
they are advanced in the areas Strategy and
Management and Customer and immature in
the area of the Environment and Society.
Additionally utilities were asked to identify their
targeted goals for each of the groupings.
Overall, Kentucky utilities reported they would
like to be mature in the areas of Strategy and
Management and Customer classes, with
roughly equal, but lower, emphasis on the
importance of the remaining areas.








20

The KSGAM also identified seven technological independent abilities of the Smart Grid. These abilities,
called Smart Grid Characteristics, are:
1. Active Participation by Consumers (APC): increased interaction of consumers with the grid,
characterized by the use of price based signals and demand response programs to give
customers choice and control regarding power purchasing.
2. Accepts All Power Generation and Storage (AAPGS): integration of diverse resources with “plug-
and-play” connections to multiply the options for electrical generation and storage, including
large centralized power plants, distributed energy resources and energy storage devices.
3. Enables New Products and Services (ENPS): Direct linking of the buyers and sellers of electricity,
the advent of new commercial goods and services and a restructuring of power markets.
4. Improved Power Quality (IPQ): The delivery of “clean” digital-grade power characterized by a
reduction in under voltage sags, voltage spikes, frequency harmonics, and phase imbalances.
5. Efficient Operation and Use of Assets (EOUA): Use of real time information from advanced
sensors to allow operators to better understand the state of the system.
6. Self-Healing: The grids ability to identify, isolate, and restore problematic sections of the grid
with little or no manual intervention.
7. Defend against Attack and Natural Disaster (DAAND): The grids ability to protect against physical
attacks (explosive, projectiles, and natural disaster) and cyber (computer-based) attacks.
Stakeholders were given detailed descriptions
of each of characteristic and were asked to rank
them on a scale from 1 to 5, with 1 indicating
that the current electric power system does not
implement any aspects of the ability, and 5
indicating that system implements all aspects of
the characteristic. Stakeholders also reported
the level of advancement they felt was
important to a future modern grid, using the
same scale. The survey indicates that
stakeholders perceive the current grid to be
most advanced in Efficient Operation and Use
of Assets and that the desired future grid is
advanced in the areas of Active Participation by
Consumers, Accepts All Power Generation and
Storage, and Efficient Operation Asset Use.








Stakeholders were also asked to allocate $100
million amongst improvements in the electric
power system in five areas. This activity
indicated that Kentucky stakeholders would
most like to see improvements regarding the
environmental impact of the electric grid.

Economic Valuation of Smart Grid Benefits
S
MART
G
RID
B
ENEFIT

A
VE
.

V
ALUATION

Reliable

$18.55M

Secure and Safe

$17.13M

Economic

$19.95M

Efficient

$19.63M

Environmentally Friendly

$24.75M

21

THE STATE OF ADVANCED METERING INFRASTRUCTURE
The fundamental purpose of AMI is to establish two-way communication with the
consumer and to provide time stamped system information regarding electrical power
data.
AMI Nationally
Nationally, AMI deployments have received a great deal of interest from both utilities and regulatory
commissions due to their ability to facilitate the usage of time-based rates. Although some case studies
have shown great benefit, others have been met with resistance, particularly when customer’s
consumption behavior does not change.
PowerCentsDC
The PowerCentsDC pilot was initiated to test the
impacts on consumer behavior of dynamic pricing
and smart metering in the District of Columbia.
From July 2008 through October 2009,
approximately 900 residential customers were
randomly selected across D.C. area to participate
in the pricing pilot on three price plans: critical
peak pricing, critical peak rebate, and hourly
pricing. Results from the pilot project showed that
residential customers responded to dynamic
pricing and saved money by cutting their
electricity consumption. The results also suggest
that the critical peak pricing which hiked
electricity rates to five times than normal led to
the greatest peak demand reductions while the
critical peak rebate was most popular. It was
found that limited-income customers signed up at
higher rates and resulted in less peak reductions
than others on the program. Over 74 percent of
participants were satisfied with the program, over
93 percent expressed a preference over the
default pricing plan
3
, and about 89 percent would
recommend the pilot to their friends and family
according to the customer surveys conducted
following the completion of collection of data in
November 2009.
Pacific Gas and Electric

3
(
http://www.pepco.com/_res/documents/DCRates_R.pdf
)
The AMI system is composed of a number of
integrated technologies that include:
Smart Meters
Smart Meters are solid state programmable devices
that improve upon electromechanical and AMR meters
in that they offer additional functions that include
support for time-based pricing, consumption data for
consumers and the utility, , and communication with
intelligent energy devices within the customer home.
Additional advantages of smart meters are that they
can be used to enable a variety of additional Smart
Grid projects such as advanced Demand Response and
Volt/VAR control and they help to facilitate greater
energy efficiency through information feedback to
consumers.
Meter Data Management System
A MDMS is a database system that is combined with
analytical tools that enables Smart Meter data to be
utilized in conjunction with other information systems
such as Consumer Information Systems, Geographic
Information Systems, and Transformer Load
Management.
22

A lawsuit was filed on behalf of customers in
Bakersfield, California where a $2.2 billion
smart meter project was rolled out by PG&E.
Bakersfield residents experienced much higher
electricity bills than before and believed that
malfunctions of the newly installed smart
meters were the reason. Contrarily, PG&E
claimed higher bills were due to high rates of
peak pricing, an unusually warm summer (2009)
and customers’ not shifting demand to lower
off-peak rates. Critics contend that PG&E was
unsuccessful in informing customers about the
value of shifting demand or the time of energy
consumption to lower-priced off-peak time.
Additionally, PG&E neither rolled out in-home
displays along with their smart meter rollouts,
nor did they have an effective system in place
where customers could access energy usages,
see electricity rates, or receive alerts.
AMI Deployment Highlights in Kentucky
Overview
In Kentucky, 15 of the 23 jurisdictional utilities operate systems containing smart meters, and
penetrations rates vary from 1 percent to 100 percent of residential customers, with an overall
penetration rate of 22 percent. All of the AMI capable utilities have implements Power Line Carrier as
the WACS architecture. Two utilities utilize HANs to communicate with in home devices, including
programmable communicating thermostats, load control switches, programmable water heaters, and
in-home-displays. Four of the utilities utilize a MDMS to enable AMI data to support other Smart Grid
functions.
Jackson Energy Cooperative’s Prepay Metering
Jackson Energy Cooperative (JEC) serves consumers in fifteen counties in SE Kentucky, three of which
are low in median household income. Currently, JEC has 100 percent of customers are served by AMI,
and JEC has leveraged the AMI system through the implementation of Prepay metering in order to assist
members in energy conservation and bill reduction, and to enable customers to take control of their
monthly electric bills. The Prepay program was rolled out to all cooperative members on June 27, 2011
and currently has 1,303 member participants. Members pay for their electricity before they use it, in
dollar amounts and times of their choosing, using the same payment methods available to all Jackson
Energy members. JEC issues an in-home display (IHD) to the member and installs a disconnect collar at
the member’s meter base, enabling the monitoring of electric usage via and In Home Display showing
usage patterns and daily kWh consumption.
The AMI system is composed of a number of
integrated technologies that include:
Wide Area Communication Systems
A digital communication infrastructure must be
deployed to enable bi-directional data flow between
the customer smart meter and the utility. While
various media can be employed, the WACS system can
serve as the foundation for a multitude of Smart Grid
applications beyond AMI.
Home Area Networks
The HAN interfaces the Smart Meter with controllable
electrical devices within the consumer premise. It
support energy management functions including in-
home displays to provide consumers with usage data,
responsiveness to price signals, control of load such as
smart appliances and smart thermostats, and
consumer over-ride capability.
23

The ability to monitor and manage energy usage helps participants to conserve energy which has
resulted in an average reduction of 1312 kWh (≈13 percent) as compared to those not on Pre-pay
metering. The average monthly reduction is 312 kWh. Additionally, deposits are not needed and there
are no late payment penalties, saving members hundreds of dollars in additional costs to obtain electric
service. All of these items give cooperative members greater flexibility in paying for electricity. The
cooperative benefits from a reduction in costs related to disconnects/reconnects and a reduction in bad
debt or write-offs. All of the above results in higher member satisfaction.
Owen Electric’s Smart Home Project
Owen Electric is researching emerging and innovative energy management programs and viable rate
designs for the benefit of members. They are currently recruiting participants for a Smart Home pilot
that will evaluate smart home technologies and capabilities by offering detailed energy usage
information through a home energy network. In addition, the Smart Home pilot will enable members to
automate aspects of their energy usage through a home wireless network controlled within the home
and remotely through a website or mobile phone. Lastly, the pilot will incentivize members to reduce
peak usage through the deployment of a time of day (TOD) rate.

Approximately 300 customers will participate in
the pilot: 100 with web experience only, 100
low income families with web experience and
smart water heater control device and a smart
thermostat, and 100 none-low income families
with web experience and smart water heater
control device and smart thermostat. One of
the goals of the project is to create a smart
home that is projected to be economically
viable and is eventually planned to be a
standard offering with an approved PSC tariff.
The total pilot will cost approximately $1.1M
with half of that being paid for by a DOE grant.
As stated above the member savings benefit
will be based on their energy reduction and
shifting from peak to off peak and Owen’s
savings will come from the monthly demand
reduction. The viability of the project will be
determined by those factors.


Key Recommendations on AMI
Critical benefits can be leveraged by installing
WACS architectures that support not just AMI,
but any Smart Grid application. Therefore the choice of WACS architecture should start at the network
layer as opposed to the application layer. The recommendation of the KSGRI is, therefore, the use of a
deliberate architecture designed using Internet Protocol (“IP”) based networks that support any
application. This focus on the network is in stark contrast to the traditional use-case that starts with a
compelling application and then installs the communication infrastructure to supports it. Two reasons
drive this recommendation: 1. based on trends in a variety of other industries and on successful
An online energy information system provides detailed
utilization data to consumers, enabling informed decision
making regarding the use of electricity.

24

deployments nationally, it is the opinion of the KSGRI that fundamentally, Smart Grid will be driven by
two-way data transfer and long-term successful implementations are those that design a network to
support this, as choosing different network architectures for different applications will create long term
integration problems that can be fatal to the overall Smart Grid value equation. 2, an IP network is the
best candidate for a future-proof WACS architecture that can support any and all smart Grid
applications, including those beyond AMI deployments. Additionally, the majority of use cases have
shown that to gain full demand response benefits from AMI deployments, a holistic approach must be
taken that includes both dynamic rates and automated customer control. Therefore, it is the
recommendation of the KSGRI that AMI deployments must address the following criteria:
1. Provide electronically communicated digital price signals: Automated price, reliability, and
event signals should be provided to customers along with a means to display information on a
wide variety of interfaces.
2. Provided signals should follow open, non-proprietary standards that can be used to directly
activate customer energy related systems and controls such as smart appliances and energy
management systems.
3. Provided signals should integrate prices and incentives that motivate customer to purchase
more efficient appliances and to provide price-responsive demand. Such incentives should be
ongoing and integrated into the underlying rate/price signal.
It is important to note that even good rate designs that are badly executed or not accompanied by
appropriate customer education, tools and technology can produce ineffective results, therefore the
KSGRI recommends that all AMI deployments proposals be accompanied by a practical implementation
plan that address the following key issues:
1. The transition of customers from existing flat and tiered rates to dynamic rates.
2. The education of customers regarding both the opportunities and risks.
3. Technology assessment regarding availability of devices to enable customer automation of
response.
4. Plans to identify and mitigate potential adverse bill impacts.

25

THE STATE OF DISTRIBUTION
Advanced Distribution Operations enable a grid that self-heals through auto-detection of
faults and auto-reconfiguration of circuits, that is more efficient due to advanced system
modeling and analysis and Volt/VAR control, that is more flexible and situationall aware
due to advanced sensing, data acquisition, and automated control. The distribution
system of the future will enable both the incorporation of Distributed Energy Resources
and will operate with novel circuit configurations such as microgrids.
ADO Nationally
Nationally, ADO deployments have been evenly divided between automating many of the functions of
the low voltage distribution system (distribution level SCADA deployments), particularly at the sub-
station-level, and of energy efficiency improvements such as capacitor installations and Volt/VAR.
SmartSacramento Project
Sacrament Municipal Utility District’s (SMUD) Smart
Sacramento Project is evaluating the benefit of a
partial deployment of advanced distribution assets
that equipped distribution circuits with automated
control and operation capabilities, as well as the
integration of plug-in electric vehicle charging
stations to assess their effects on electric distribution
system operation. SMUD installed distribution
automation equipment on 16percent of circuits in
the range of 12kV to 69kV. This included a
communications network, automated circuit
switches, automated capacitors, and equipment
monitors. The equipment automatically responds to
power disturbance and provided voltage regulation
and isolates interrupted circuits. The goal is to
evaluate the system for potential to reduce service
interruptions, the frequency and duration of
outages, and the number of truck visits. SMUD also
expects DA too assist the grid integration of solar
and wind installed at the distribution level. Results
from the SMUD deployment are expected for release
in Q1 of 2013.
AEP’S gridSMART
American Electric Power’s griSMART deployments
include Volt/VAR optimization on 11 circuits in AEP
Ohio. The Volt/VAR optimization project, a
technique also known as conservation voltage
ADO infrastructure utilizes the following technologies
to improve the reliability and efficiency of the
distribution system:
Fault Location, Isolation and Service Restoration
FLIR technologies automatically detect faults,
determine the faulted section and location, and
calculate optimal solutions for restoring service.
Data Acquisition and Control
DAC (i.e. distribution SCADA) is the collection and use
of real time data to issue control commands to
automate power system equipment operation and
parameter settings.
Distribution System Modeling and Analysis
DOMA is the modeling and analysis of distribution
power flow under dynamically changing operating
conditions. It is used to provide system operators with
real-time power flow simulations and contingency
analyses for system optimization.
Volt/VAR Control
VVC is the calculation of the optimal settings of
voltage controls for distribution equipment. The most
common uses of VVC are Volt/VAR Optimization, the
control of voltage to optimize power transfer, and
Conservation Voltage Reduction, energy conservation
by reduction of the voltage supplied to the end-user.
26

ADO infrastructure utilizes the following technologies
to improve the reliability and efficiency of the
distribution system:
Distributed Energy Resourced and Microgrids
DERs can help support local power grids in case of
outages or blackouts and can ease the loads on long-
distance transmission lines. However, they can also
destabilize the grid if not managed appropriately. A
microgrid is a localized group of electricity sources and
loads that can disconnect from the larger system to
operate autonomously.

reduction or Volt VAR control (VVC), utilizes
communications and computerized intelligence to
control voltage regulators and capacitors on the
distribution grid which will optimize voltage and
power factor based upon selected parameters.
Computer algorithms use monitoring and feedback
to ensure that the minimum voltage requirements of
the end-of-line are maintained. By tightly operating
the distribution system at the lower end of the
service voltage, AEP Ohio has shown a reduction in
customer energy consumption of 2.9 percent and a
peak demand reduction of between 2 percent and 3
percent. Through VVC AEP Ohio has shown a potential reduction in demand of 10’s of MW, thereby
reducing the amount of capacity to be replaced or upgraded. Additional benefits are related to meeting
state energy efficiency targets, reducing emissions, and relieve transmission congestion.

ADO Deployment Highlights in Kentucky
Overview
Use of real time data from the distribution system to perform distribution system analysis and modeling
is infrequent in Kentucky and is currently only being evaluated in one pilot project. However, two
utilities have reported plans for near term deployments (<5 years). Most utilities do utilize DOMA for
off-line modeling to calculate “what-if” power flow values, and these practices are well established
within the industry. However, few utilities extend the DOMA analysis to the transmission and/or sub-
transmission systems. Three utilities operate Fault Location, Isolation, and Service Restoration(FLIR)
pilot projects, and one utility indicated planning to implement FLIR as part of future Distribution
Management System upgrade. Currently, overall penetration rates are low (<4 percent). All three pilot
systems are capable of performing automatic location, isolation, and restoration of faulted circuits, and
are operated in the closed loop mode. The FLIR data sources utilized in these programs come only from
SCADA systems and do not interact with other advanced data sources. Ten of the responding utilities
report utilization of distribution level DAC for data retrieval and control commands issued to power
system equipment and devices in the field, largely identified as a component of distribution level SCADA
systems. Penetration rates of DAC vary widely across the state, raging to 0 percent of distribution level
substations to 100 percent. One utility has extended the use of DAC to facilitate monitoring control of
distributed generation and microgrids. No utilities reported utilization of Volt/VAR. Two utilities have
indicated planned Volt/VAR pilots.
Kentucky Power’s Automated Circuit Reconfiguration
Kentucky Power has installed Automated Circuit Reconfiguration (CR) on seven circuits that serve
approximately 11,000 (6 percent) of its customers. CR utilizes communications and intelligence to
automatically open (de-energize) switches to isolate a faulted section of line and then automatically
close (re-energize) tie switches to restore service to the customers in the un-faulted zones. Only the
customers in the section of line where the fault occurs experience a sustained outage. Customers in the
27

other line sections are immediately transferred
to another source thus limiting their outage to
only a momentary interruption. The CR
installations utilize S&C IntelliTeam technology
applied to substation circuit breakers, line
reclosers, and line switches. SCADA is utilized to
provide dispatchers with visibility of circuit
conditions and the ability to remotely operate
devices.


So far, the installation cost is approximately
$2.5 million. Costs of future CR are challenging
to predict due to the effect of Eastern Kentucky
terrain on communication requirements and
the need to modernize SCADA communications
at most of the substations. Industry experience
projects a 30 percent to 50 percent reduction in
sustained customer outages when this
technology is utilized. To date, CR technology
has saved approximately 18,000 customer
outages and 4,800,000 customer minutes of
outages on the seven circuits. CR is being planned for an additional seven circuits serving approximately
7,500 customers in 2012. Upon completion, it is expected a total of 14 circuits serving 18,500
(11 percent) of Kentucky Power customers will have CR in operation. Additional installations are being
studied along with more traditional reliability improvement alternatives to develop future reliability
improvement plans.

Kentucky Power’s Volt/VAR Optimization
Kentucky Power is considering installation and operation of Volt/VAR technology on approximately 25
circuits. This is estimated to reduce peak demand by approximately 7 MW and energy usage by
approximately 34,000 MWh/year. These levels of demand and energy benefits are achieved by installing
distribution automation Volt/VAR control schemes which integrate distribution capacitor/regulator
banks and transformer load tap changers with a centralized control system to flatten the voltage profile
and lower the delivery voltage level at the substation by approximately 3 percent to 4 percent. These
systems have been demonstrated elsewhere and have been able to maintain voltage above the ANSI
standard service range of 114 volts for all customers on a distribution feeder. In addition to achieving
the demand reduction and energy efficiency savings, the deployment of this technology will provide a
technology infrastructure that could be combined with a distribution management system to provide
operational and other reliability improvements. Installation of VVC equipment on the initial distribution
feeders in Kentucky is estimated to cost approximately $250,000, however, costs may be higher due to
the effect of Eastern Kentucky terrain on communication requirements and the need to modernize
SCADA communications at most of the substations.
Automated switches mounted to utility poles can be used
to create self-healing grids that improve reliability by
isolating faulted sections of the distribution system.

28

Owen Electric’s Volt/VAR Optimization Project
Owen Electric is enhancing its knowledge of the effects of optimizing system voltage and kVAR profiles
in respect to peak electrical demand and energy usage. The Volt/VAR optimization project involves six
feeders fed from two substations and is sequenced in four phases:
1. Verify and correct system data so that engineering models are accurate in all critical areas.
2. Analyze and optimize feeders for phase balancing and power factor.
3. Test and evaluate effects of reducing voltages on the feeders.
4. Deploy IVVC (integrated Volt/VAR control) system at one of both test substations
The technology and equipment used in the project include:
1. Global Positioning System Equipment
2. ABB GridSync Monitors
3. Voltage Regulators
4. Switched and Fixed Capacitor Banks
5. Engineering Analysis Software
6. IVVC Equipment
Cost projections at this time are $537,200. Throughout the project cost/benefit analysis will determine
the benefit of project continuation and/or expansion. Regardless of the outcome, the Volt/VAR project
will serve as a case-study for Kentucky distribution companies.
Key Recommendations on ADO
Conservation voltage reduction (CVR) pilots such as those performed by EPRI and AEP have shown
overall energy savings from 1 percent to 6 percent, with 2 percent to 3 percent quite typical. Kentucky
regulations should therefore ensure that saving energy on the “customer side” of the meter through
conservation programs such as CVR Volt/VAR does not reduce utility revenue. Additionally, advanced
distribution system modeling and analysis is not being utilized in Kentucky. It is the recommendation of
the KSGRI that such tools be utilized in all future resource planning in the state, particularly to evaluate
the benefits of energy efficiency and renewable energy technologies against the addition of generation
capacity from fuel-based sources.

29

THE STATE OF TRANSMISSION
Advanced Transmission Operations utilize advanced digital technologies and new power
electronics to increase system performance, enable the interconnection of isolated
power systems, improve the size and capacity of existing transmission assets and
improve the ability of system operators to control the system across markets.
ATO Nationally
Nationally, Advance Transmission (“ATO”) deployments have focused on the installation of
synchrophasor technology to improve transmission reliability and operation. Synchrophaser
technologies use Phasor measurement units, Phasor data concentrators, and wide area communications
networks to create time-stamped data regarding current and voltage across the transmission system,
often referred to as an “EKG of the electric system”. Additionally, technologies are being deployed to
dynamically rate and operate transmission assets based on environmental variables. Currently there is
also a great deal of discussion regarding creation of high capacity high voltage direct current (HVDC)
transmission that will connect large central wind and solar farms to load center. Thus far, little
investment has been made in development of such a system.
Western Interconnection Synchrophasor
Program
The Western Electricity Coordinating Council
and eight member transmission companies are
deploying synchrophasor technology
throughout the Western Interconnection. The
purpose of the project is to improve electric
system reliability and restoration procedures
and to prevent the spread of localized outages.
Additionally, the project will improve the ability
of the Western Interconnect to integrate large
renewable resources. 341 phasor measurement
units, 50 phasor data concentrators,
transmission system communication
equipment, and advanced software applications
will increase grid operators’ visibility of the bulk
power system, enabling them to visualize the
conditions in near-real time. Such fine-grained
visibility will enable earlier detection of
problems, facilitates the sharing of information
with neighboring control areas, and allows the
continued improvement of power system
models and analysis tools.
ATO Deployment Highlights in Kentucky
ATO infrastructure increases the size, capacity, and
intelligence of the existing transmission system:
Automated Control
Remotely controllable equipment and advanced
computer algorithms can automatically control the
voltage, load, and circuit configuration. This can be
applied to optimize normal operations or to quickly
address emergency situations.
Wide Area Monitoring
The deployment of synchrophasor technology will give
an unprecedented level of detail of the grid operations
and health. By sharing PMU and SCADA data
nationally, transmission operators can more finely
control the transmission system, helping to prevent
both congestion and systemic failure.
Dynamic Equipment Rating
New technologies allow equipment to be utilized
closer to actual capacity, which can increase overall
system capacity and extend equipment lifetimes.
Advanced Components
New components will extend the amount and distance
over which electrical power can be efficiently
transmitted.

30

Overview
Overall the transmission system of Kentucky is highly sophisticated and interconnected. However, the
degree to which new smart transmission operations have been applied in Kentucky varies greatly across
the four transmission operators. Automated Control (“AC”) of the baseline functions of the transmission
system in Kentucky include automatic voltage regulation and automatic reactive load control,
interlocking and sequencing of controls within transmissions substations to prevent unsafe operations,
automatic load adjustment of load to balance line-loading conditions, and automated system
restoration via computer control of switches and breakers. In emergencies, the utilities can
automatically isolate faults and can shed load. Some of the transmission system is equipped with
automated reclosers and motor operated air break switches, but the penetration of such technologies
statewide is minimal. Several transmission operators are utilizing dynamic ratings for transmission line
utilization, however the sophistication of these approaches varies dramatically amongst the operators.
Relatively few advanced components have been utilized in the Kentucky transmission system. Upgrades
have been focused on high temperature and high capacity cable and fault current limiters, with one
flexible AC transmission system installation.
LG&E-KU Energy Smarter Transmission System
LG&E-KU Energy, is creating a smarter
transmission system through the use of
microprocessor based relays, local substation
networks, and communications processors. The
use of microprocessor based relays provides
numerous benefits over the traditional
electromechanical relay including capture of
event data with a high precision time stamp.
These relays also provide numerous functions
within a single box, replacing up to nine discrete
devices with a single relay. A local network
connecting the microprocessor relays provides
automation and labor savings through remote
access that allows:
1. gathering detailed event data remotely
2. querying and updating relay settings
remotely
3. monitoring the status of the system and
equipment in greater detail
4. gathering and distributing Synchrophasor data
LG&E-KU is implementing these new technologies through the use of drop-in control houses that are
built off site with the new technologies pre-installed and wired, which enables LG&E-KU to install, test,
and commission new equipment in a relatively short time frame, reducing system impacts.
Dynamic Ratings at East Kentucky Power Cooperative
Microprocessor relays are capable of capturing event data
such as the shape of input currents and voltages,
communications inputs, equipment status inputs, and
relay outputs, all with a high precision time stamp.
31

The amount of current that equipment can
carry is a function of ambient temperature and
cooling provided by the wind and often
“benchmark” environmental conditions and
other factors are combined to calculate
seasonal ratings for equipment. At times, there
is significantly more transmission line and
transformer capacity than the standard static
ratings state. Capturing this additional capacity
is the essence of dynamic ratings, such as the
Dynamic Thermal Circuit Rating (DTCR)
technology utilized by EKPC.
The first phase of this project provided dynamic
ratings for a 138kV transmission line and a
345/138kV power transformer. A fully
instrumented weather station was installed
near the assets and is polled every 10 minutes.
The DTCR software combines weather data with
real-time transmission line and transformer
power flow data via an Energy Management
System interface to provide a near real-time dynamic rating. A graphical user interface (GUI) was
developed in-house at EKPC to display dynamic ratings on a dedicated screen readily available to the
transmission dispatcher. In phase II, EKPC dynamically rated an additional six 138kV transmission lines,
two 345/138kV power transformers, and installed a second weather station.
In the summers of 2006 and 2007, EKPC was experiencing extremely high power flows on a 345kV
transmission line due to huge non-contracted north to south power transfers between neighboring
utilities. During these power trades additional capacity provided by dynamic ratings allowed delaying of
re-dispatching efforts, saving EKPC nearly $1.5M.
Key Recommendations on ATO
Based on the current situation in Kentucky, the KSGRI would recommend several promising technologies
in order to improve the overall reliability of the transmission system. The dynamic thermal rating
application may be utilized by transmission operators in Kentucky to increase the utilization of existing
transmission assets without significant investment to build additional lines. More advanced fault
location and restoration systems can be employed to protect the system from disturbances, and reduce
outage time. Synchrophasor technology using PMUs may be deployed to provide transmission operators
with improved wide area grid monitoring and awareness, and may help prevent large-scale blackouts
along with the SCADA system.

EKPC weather station mounted on the Dale to Avon
138kV transmission line. The weather station is polled
every 10 minutes to provide near real-time dynamic
ratings for the transmission line and power transformer.
32

THE STATE OF ASSET MANAGEMENT
Utilities are getting more detailed data about equipment from meters, sensors, and
intelligent energy devices. Advanced asset management is the utilization of that data to
make better informed decisions regarding the utilization and operation of assets.
AAM Nationally
Unlike AMI, ADO, and ATO, asset management has not seen federally funded demonstration projects.
Instead, AAM has been developed by data analytics companies including Boeing, IBM, Cisco, and
Utilicase. Advanced asset management (“AAM”) can provide benefits such as a more comprehensive
picture of asset health, prevention of catastrophic failure, improved return on investment on
maintenance, and more intelligent investment decisions and sophisticated risk analyses. Additionally,
AAM can increase the utilization factors of grid assets, thereby eliminating, reducing in scope, or
deferring the construction of capital resources.
National Statistics
Estimates from the Horizon Energy Group show the national capacity factor of the U.S. generation
portfolio to be approximately 47 percent. This suggests that additional capacity is available for
production. On average, transmission lines are loaded to 43 percent and distribution asset utilization is
34 percent; however, line flows can be limited due to congestion at specific times. Also, over 12 million
distributed generation resources are located on consumer premises, with the vast majority of them not
grid connected. This all suggests that opportunities exist to better utilize existing resources as opposed
to new construction.
Hydro-Québec TransÉnergie
Hydro-Quebec TransEnergie operates the largest transmissions system in North America, consisting of
514 substations and over 33,630 km of transmission line, much of which was built between 1960 and
1980. By the mid-2000s much of the transmission system equipment was beginning to near its useful
lifespan. For example, the average age of circuit breakers, with a useful lifespan of 30 years, was 23
years.
To facilitate the necessary upgrades of the transmission equipment, Hydro-Quebec installed strategic
asset management tools that collect data from the transmission data acquisition system and perform
analytics to improve asset utilization. The system implemented by Hydro-Quebec focused on
maintenance optimization and software upgrades that assist in maintenance planning, helping the utility
to decide which equipment has reached the end of its useful life cycle. The software implementation
consisted of three modules. An equipment module created a digital inventory of equipment that groups
equipment as systems to manage relationships between systems and their constituent components.
The laboratory and reading module transmits equipment field test data to a secure data center. When
field tests are performed, information and instructions are available to field preparation on line. By
reporting via online forms, out of range test values are immediately flagged for additional verification by
on-site personnel. The analysis module provides statistical and analytical reports on equipment
behavior. This information is sent to decision support tools that re-orient management parameters to
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optimize maintenance. This module also includes a digital maintenance log that provides a statistical
failure comparison of preventive maintenance costs vs. repair costs after equipment failure.

AAM Deployment Highlights in Kentucky
Overview
Overall advanced asset management is immature in Kentucky, particularly with regard to automated
gathering of real-time raw data to support asset management decisions. Instead, most strategic asset
management investments have continued to rely on manually collected data, with a slow change from
condition and reliability based maintenance and utilization to predictive maintenance and probabilistic
risk assessment. Three utilities report the utilization of automated sensors to monitor factors such as
vibration, chemical analysis, acoustics, temperature, or other non-electrical parameters used in the
delivery of electricity, while overall penetration rates of such technologies are very low (<5 percent).
However, even when these sensors are installed, they are not linked to data input into a common
information model. Such models are infrequently utilized by the Kentucky utilities, and require manual
input of data. As such, there is limited use of real time data to improve maintenance and repair
schedules. As a result, most utilities still perform reliability based maintenance, although some do
utilize real asset data to calculate reliability indices. Some condition based maintenance programs have
been implemented, particularly as related to SCADA. In regards to operational optimization, no utilities
currently utilize automation to actively optimize asset utilization, although there are a small number of
circuits in the state which are reconfigurable to minimize system loss. While there is some dynamic
operation of transmission lines and transmission transformers, penetration of such operation is very
small and has not been applied to distribution level equipment.
Key Recommendations on AAM
Advanced asset management is not currently being performed in Kentucky. To enable AAM, the KSGRI
recommends increased deployment of sensors that provide the operational and health status of all
important assets, and the installation of analytical tools and capabilities to better optimize system and
human assets. It is the opinion of the KSGRI that the wide area communication infrastructure necessary
to enable ubiquitous AAM throughout Kentucky should be considered in any business and/or rate case
related to any or all of the following: AMI, ADO, and ATO.



34

THE STATE OF DISTRIBUTED ENERGY RESOURCES
Distributed Energy Resources that include distributed generation, electric vehicles, and
energy storage devices can help increase grid reliability, can help to manage peak loads
and defer capital investments in T, D, and G, can lower emissions, and can improve
overall system security. However, most are not yet cost-competitive with traditional
generation sources and will require more sophisticated integration strategies as
penetration rates increase, as well as new pricing models for electricity.
DER Nationally
The U.S. Department of Energy has funded nine renewable and distributed systems integration
demonstration projects that utilize microgrids and DERs to achieve a 15 percent reduction in peak load
on distribution feeders and substations. Additionally, the systems are designed to operate in grid
parallel or as islanded systems.
The Pecan Street Energy Internet Demonstration Project
The Pecan street project developed and implemented an Energy Internet microgrid in a large mixed-use
infill development in Austin Texas. The redesigned energy system integrates energy efficiency,
distributed renewable energy, local energy storage, and enhanced user-controlled energy management
tools that include smart appliances all through an open architecture for “plug-and-play. Currently, the
Austin-based Incernergy LLC has deployed a home Smart Grid system that captures minute-to-minute
energy usage for the whole home and six major appliances or systems at an installed cost of $341 per
home. The systems have been deployed in 100 homes, 11 of which have rooftop solar PV systems.
During this first phase, researchers are learning about how homeowners use electricity, gas and specific
appliances through the day. Using the information from the initial deployment, next generation home
Smart Grid systems will be developed and deployed in 1,000 residential and 75 commercial customers.
These systems will also integrate 100 Chevrolet Volts with in-home charging capacity. All participation
in the project is voluntary.
SmartGridCity project by Xcel Energy Boulder, Colorado
The SmartGridCity project by Xcel Energy in Boulder, Co. is one of the most widely publicized
experiments in bringing Smart Grid to an entire city, and has been seen as a pioneer for demonstrating
some of the most important Smart Grid technologies. There's no doubt that SmartGridCity has achieved
impressive grid optimization applications and reliability improvements. However regulators and
ratepayers believe it has been a massive failure in terms of the cost overruns and the fact that
customers still don't have sufficient tools to easily monitor and reduce energy usage.
According to multiple sources, several key factors that have contributed to the problems are:
1. Xcel didn’t file a Certificate of Public Convenience and Necessity (CPCN) before the project
started in 2008, because they didn’t think it was needed for a research project. Without a CPCN,
there was no opportunity for the Public Utility Commission to consider capping costs to protect
ratepayers
2. A traditional simple cost-benefit analysis wasn’t performed prior to the initiative, and the
project costs ballooned from the original estimate of $15.3 million to last reported $44.8 million
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mainly due to higher costs of permits, tree trimming, software; and installing fiber optic
communication lines. Xcel sought from the PUC to approve a rate increase to recover some of its
project costs. That was when the PUC decided Xcel needed a CPCN to prove the project is
prudent and in the public interest
3. Several key Xcel project executives left early in 2009 which had a negative impact on the project
management.
4. As the project approaches completion, only 43 percent of Boulder residents have smart meters,
which is a very low number for a supposed Smart Grid leader. Additionally, the metering system
is not providing as many in-home benefits anticipated as part of a Smart Grid program.
Fort Collins 3.5MW Mixed Distributed Resources for Peak Load Reduction
The FortZED project is an integrated system of 3.5 MW of mixed distributed resources in Fort Collins,
Colorado to achieve a 20-30 percent peak load reduction on two distribution feeders. The integrated
DERs are at the following sites:
· Site 1: New Belgium Brewing -- deploys new 200 kW PV arrays with AE inverters; a 292-
kW methane-based Gauscor CHP; a 650 kW CAT 3508C methane-based CHP; a 135 kW
new thermal storage; and a 160-kW load shedding potentials.
· Site 2: InteGrid Laboratory -- deploys 2x80 kW Onan natural gas genset; a 300 kW CAT
natural gas genset; an 80 kW Ingersoll Rand microturbine; an 80 kW Bowman
microturbine; a 100 kW wind turbine simulator; and a 10 kW fuel cells.
· Site 3: City of Fort Collins Facilities -- deploys a 50 -kW conventional generator with
Woodward controls and Eaton switchgear; a 92 kW thermal storage; a 5 kW PV array; a
62 kW HVAC and DSM; and 2x10 kW Ford Escapes (PHEVs).
· Site 4: Larimer County -- deploys a 10 kW new PV array; and a 2x1 HP motors for water
fountain control.
· Site 5: Colorado State University - deploys an 80 kW thermal storage; an 80 kW fan
variable speed drives; a 21.6 kW water fountain pumps; a 3.6 kW hot water heater
controls; a 6 kW daylight control, and a 950 kW conventional gensets with Woodward
controls and Eaton switchgear.
DER Deployment Highlights in Kentucky
Overview
Installation of DERs in Kentucky is primarily composed of fuel sourced combustion generators, with 4.4
MW of diesel generation and 14.4 MW of natural gas generation. Also, as reported by utilities, there are
20 kW of installed solar PV on the Kentucky distribution system. The members of the KSGRI recognize
that this number is artificially low, as many roof-top solar installations were not reported. Currently, no
distributed storage is deployed in Kentucky. While EV penetration in the state is unknown, only one
utility reported having a structured Electric Vehicle integration strategy.
The KSGRI characterizes the development of DERs in Kentucky as very immature. This is largely due to
the factor of the low electricity rates in the state and the use of net metering agreements as opposed to
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feed-in tariffs coupling to create an economic climate that is unfavorable for DER adoption by
customers.
Key Recommendations on DER
Although not currently cost competitive with tradition fuel based energy sources, locating DERs
physically near load centers can reduce the need for capital upgrades to the transmission and